In a fluid processing plants, the plant operating company may or may not own all of raw feed stock. Feeds may come from differing sources, and the operating contracts for product fluids may be different for varying sources. Also, the economics of operation are dependent on inlet compositions, flow rates, current prices on various spot markets, and contractual requirements on products. As a result, plant optimization requires detailed real-time analysis of multiple input and product streams.
From a processing perspective, raw inlet fluid may be from nearby oil or gas fields, be a product of another type of process, or be associated oil or gas from oil field operations. Each has a different composition, and may have different owners. During processing, the facility must be able to account for all compositional changes along the process and how it affects different owners, while also optimizing yields and cash flow.
In addition, some components of the composition may be more desirable than others. For example, condensate has been coming in from gathering systems for years and has been handled in different ways. However, the industry's focus on liquids-rich resource plays has elevated the focus on condensates and how they should be handled. Numerous factors—varying from economical to environmental drivers—have contributed to this change in priorities, but U.S. condensate production has increased in step with activity in shale plays.
Condensate is lighter than crude oil, but heavier than natural gas liquids. The issue with condensate in its natural form is that the lighter hydrocarbons can make it dangerous to store and transport. Therefore, stabilizing is required to allow the condensate to meet specifications. Often, the condensate is pumped to a sales storage tank, where it will flash off its lighter hydrocarbon components, which usually are captured through vapor recovery compression in order to prevent venting to the atmosphere, which results in lost revenues and potential emission issues.
In many cases, however, liquids pricing makes it advantageous to further process the demethanized condensate to produce a saleable condensate product. In this case, the target specification is 9.0 psi Reid vapor pressure (RVP). To accomplish this, a second stabilizer is placed in the process immediately downstream of the first. The demethanized liquids are sent to another liquid/liquid exchanger to be warmed to 110 degrees, and are then fed to the top tray of the RVP control stabilizer.
Measuring the RVP of stabilized condensate in the midstream gathering and stabilization facilities of the more recent shale oil fields has proven to be a very difficult analysis due to the amount of paraffin in the condensate stream. RVP is defined as the absolute vapor pressure of a liquid at 100° F. (37.8° C.). True Vapor Pressure (“TVP”) is also of interest, but is much more difficult to determine in the field as it is a partial pressure calculation based on compositional analysis performed to determine the individual components of a complex fluid. From a profitability point of view, oil and gas companies would like to maximize the vapor pressure of their produced liquids while keeping the vapor pressure below any tariff or safety value set for a specific hydrocarbon product or stream. Continuous vapor pressure monitoring is desired in order to optimize the value of production streams while maintaining safe operating parameters.
Before online vapor analyzers were available, samples were extracted from process lines and taken to a lab for analysis. This demanded significant resources and, by definition, could not provide continuous vapor pressure values for a flowing line or a transportation or storage vessel in the field. Additionally, excessive care must be taken using extractive sampling methodologies to ensure that the sample taken to the lab is representative of the process stream. Fluids with high vapor pressures, which are the most critical to monitor, are subject to contamination and vapor loss leading to erroneous results, due to the propensity of the lighter molecules to “flash-off” during the sampling process or in transport to the lab. This can result in a lower vapor pressure reading than was actually present at the time of sample extraction. Therefore, the best methodology to determine vapor pressure of a process fluid would be to perform the measurement in a closed loop system at process conditions.
Conventional online vapor pressure analyzers such as, for example, ABB's RVP4500 series of products, utilize an extractive sampling system, then apply an automatic ASTM D323, ASTM D6377, or similar method to measure the vapor pressure. One of the biggest issues with these online analyzers is paraffin build-up in the system. As the temperature of the product is brought down to the 100° F. required for measurement, the paraffinic material has a tendency to drop out and clog the system, requiring extensive intervention to get back online. Also, it can take considerable time for the conventional online analyzer to complete the analysis. The cycle time is usually more than 10 minutes. Monitoring the outlet of stabilizing unit has shown that the vapor pressure can fluctuate significantly over the course of just a few minutes.
Measuring vapor pressure in the field under real pressure and temperature conditions is nearly impossible to model or calculate based on compositional values. There is no known way to, for example, take a GC's compositional values and use a look-up table or chart to determine RVP. The prior art teaches that the only known way to determine vapor pressure of a fluid is to is to measure the actual vapor pressure (i.e., measuring how much pressure a fluid's out-gassing fumes exert on a containment vessel at a given temperature). Field systems known in the art use some form of this technique to emulate the laboratory techniques to do this.
In contrast, embodiments of the present invention use information from the entire spectra of a fluid to create a chemometric model which correlates that spectra to a measured RVP or TVP value. NIR spectroscopic analyzers have been proven to be able to measure energy content, chemical composition and contaminants in-situ and in real time. Since the chemical composition, especially the ratios of hydrocarbon constituents, determines the fluid properties such as vapor pressure at given temperatures, it is possible to apply the NIR absorption spectroscopy method to predict RVP, TVP and other oil and gas properties.
There is a need, therefore, to monitor the composition of all applicable inlet and product streams and determine the optimum operating conditions for the facility, which may change over time as the economic value of various products change and to measure the RVP of stabilized condensate in the midstream gathering and stabilization facilities of the more recent shale oil fields.